Oil & Gas Wells
In the context of production from a well, oil and gas are understood to refer to crude oil and natural gas. Oil and gas are naturally occurring hydrocarbons in certain subterranean formations.
A subterranean formation is a body of rock that has sufficiently distinctive characteristics and is sufficiently continuous for geologists to describe, map, and name it.
A subterranean formation containing oil or gas is sometimes referred to as a reservoir. A reservoir is a subsurface rock body in which oil or gas is present. A reservoir may be located under land or under the seabed off shore. Oil and gas reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs) below the surface of the land or seabed.
To produce oil or gas from a reservoir, a well is drilled into a subterranean formation, which may be the reservoir or adjacent to the reservoir. A well includes a wellhead and at least one wellbore from the wellhead penetrating the earth. Typically, a wellbore must be drilled hundreds or thousands of feet into the earth to reach a hydrocarbon-bearing formation. Generally, the greater the depth of the formation, the higher the “static” temperature and pressure of the formation.
The wellbore refers to the drilled hole, including any cased or uncased portions of the well. The borehole usually refers to the inside wellbore wall, that is, the rock face or wall that bounds the drilled hole. A wellbore can have portions that are vertical, horizontal, or anything in between, and it can have portions that are straight, curved, or branched. The wellhead is the surface termination of a wellbore, which surface may be on land or on a seabed. As used herein, “uphole,” “downhole,” and similar terms are relative to the direction of the wellhead, regardless of whether a wellbore portion is vertical or horizontal.
A wellbore can be used as a production or injection wellbore. A production wellbore is used to produce oil or gas from the reservoir. An injection wellbore is used to inject a fluid, e.g., liquid water or steam, to drive oil or gas to a production wellbore.
Broadly, a zone refers to an interval of rock along a wellbore that is differentiated from uphole and downhole zones based on hydrocarbon content or other features, such as permeability, composition, perforations or other fluid communication with the wellbore, faults, or fractures. A zone of a wellbore that penetrates a hydrocarbon-bearing zone that is capable of producing hydrocarbon is referred to as a “production zone.” As used herein, a “treatment zone” refers to an interval of rock along a wellbore into which a well fluid is directed to flow from the wellbore.
Well Servicing and Well Fluids
Generally, well services include a wide variety of operations that may be performed in oil, gas, geothermal, or water wells, such as drilling, cementing, completion, and intervention. These well services are designed to facilitate or enhance the production of desirable fluids such as oil or gas from or through a subterranean formation.
A well service usually involves introducing a well fluid into a well. As used herein, a “well fluid” is a fluid used in a well service. As used herein, a “well fluid” broadly refers to any fluid adapted to be introduced into a well for any purpose. A well fluid can be, for example, a drilling fluid, a cementing composition, a treatment fluid, or a spacer fluid.
Common Well Treatments and Treatment Fluids
Well services can include various types of treatments that are commonly performed in a wellbore or subterranean formation. As used herein, the word “treatment” refers to any treatment for changing a condition of a portion of a wellbore or an adjacent subterranean formation; however, the word “treatment” does not necessarily imply any particular treatment purpose.
A treatment usually involves introducing a treatment fluid into a well. As used herein, a “treatment fluid” is a fluid used in a treatment. Unless the context otherwise requires, the word “treatment” in the term “treatment fluid” does not necessarily imply any particular treatment or action by the fluid. If a treatment fluid is to be used in a relatively small volume, for example less than about 200 barrels (32 m3), it is sometimes referred to in the art as a wash, dump, slug, or pill.
For example, a treatment for fluid-loss control can be used during any of drilling, completion, and intervention operations. During completion or intervention, stimulation is a type of treatment performed to enhance or restore the productivity of oil and gas from a well. Stimulation treatments fall into two main groups: hydraulic fracturing and matrix treatments. Fracturing treatments are performed above the fracture pressure of the subterranean formation to create or extend a highly permeable flow path between the formation and the wellbore. Matrix treatments are performed below the fracture pressure of the formation. Other types of completion or intervention treatments can include, for example, gravel packing, consolidation, and controlling excessive water production, and controlling sand or fines production. Still other types of completion or intervention treatments include, but are not limited to, damage removal, formation isolation, wellbore cleanout, scale removal, and scale control. Of course, other well treatments and treatment fluids are known in the art.
Hydraulic Fracturing
Hydraulic fracturing is a common stimulation treatment. The purpose of a fracturing treatment is to provide an improved flow path for oil or gas to flow from the hydrocarbon-bearing formation to the wellbore. A treatment fluid adapted for this purpose is sometimes referred to as a fracturing fluid. The fracturing fluid is pumped at a sufficiently high flow rate and pressure into the wellbore and into the subterranean formation to create or enhance one or more fractures in the subterranean formation. Creating a fracture means making a new fracture in the formation. Enhancing a fracture means enlarging a pre-existing fracture in the formation.
Fracturing a subterranean formation often uses hundreds of thousands of gallons of fracturing fluid or more. Further, it is often desirable to fracture more than one treatment zone of a well. Thus, a high volume of fracturing fluids is often used in fracturing of a well, which means that a low-cost fracturing fluid is desirable. Because of the ready availability and relative low cost of water compared to other liquids, among other considerations, a fracturing fluid is usually water-based.
Proppant for Hydraulic Fracturing
A newly-created or newly-extended fracture will tend to close together after the pumping of the fracturing fluid is stopped. To prevent the fracture from closing, a material is usually placed in the fracture to keep the fracture propped open and to provide higher fluid conductivity than the matrix of the formation. A material used for this purpose is referred to as a proppant.
A proppant is in the form of a solid particulate, which can be suspended in the fracturing fluid, carried downhole, and deposited in the fracture to form a proppant pack. The proppant pack props the fracture in an open condition while allowing fluid flow through the permeability of the pack. The proppant pack in the fracture provides a higher-permeability flow path for the oil or gas to reach the wellbore compared to the permeability of the matrix of the surrounding subterranean formation. This higher-permeability flow path increases oil and gas production from the subterranean formation.
A particulate for use as a proppant is usually selected based on the characteristics of size range, crush strength, and solid stability in the types of fluids that are encountered or used in wells. Preferably, a proppant should not melt, dissolve, or otherwise degrade from the solid state under the downhole conditions.
The proppant is selected to be an appropriate size to prop open the fracture and bridge the fracture width expected to be created by the fracturing conditions and the fracturing fluid. If the proppant is too large, it will not easily pass into a fracture and will screenout too early. If the proppant is too small, it will not provide the fluid conductivity to enhance production. See, for example, McGuire and Sikora, 1960. In the case of fracturing relatively permeable or even tight-gas reservoirs, a proppant pack should provide higher permeability than the matrix of the formation. In the case of fracturing ultra-low permeable formations, such as shale formations, a proppant pack should provide for higher permeability than the naturally occurring fractures or other micro-fractures of the fracture complexity. In shale fracturing, for example, small proppant, e.g., about 100 mesh size is commonly used, whereas in more permeable formations 20/40 mesh size is commonly used.
Appropriate sizes of particulate for use as a proppant are typically in the range from about 8 to about 100 U.S. Standard Mesh. A typical proppant is sand-sized, which geologically is defined as having a largest dimension ranging from about 0.06 millimeters up to about 2 millimeters (mm). (The next smaller particle size class below sand sized is silt, which is defined as having a largest dimension ranging from less than about 0.06 mm down to about 0.004 mm.) As used herein, proppant does not mean or refer to suspended solids, silt, fines, or other types of insoluble solid particulate smaller than about 0.06 mm (about 230 U.S. Standard Mesh). Further, it does not mean or refer to particulates larger than about 3 mm (about 7 U.S. Standard Mesh).
Suitable proppant materials include, but are not limited to, sand (silica), ground nut shells or fruit pits, sintered bauxite, glass, plastics, ceramic materials, processed wood, resin coated sand or ground nut shells or fruit pits or other composites, and any combination of the foregoing. Mixtures of different kinds or sizes of proppant can be used as well. In conventional reservoirs, if sand is used, it commonly has a median size anywhere within the range of about 20 to about 100 U.S. Standard Mesh. For a synthetic proppant, it commonly has a median size anywhere within the range of about 8 to about 100 U.S. Standard Mesh.
The concentration of proppant in a fracturing fluid depends on the nature of the subterranean formation. As the nature of subterranean formations differs widely, the concentration of proppant in the fracturing fluid may be in the range of from about 0.03 kilograms to about 12 kilograms of proppant per liter of liquid phase (from about 0.1 lb/gal to about 25 lb/gal).
Coated Proppant for Hydraulic Fracturing
One common problem is that the proppant may not be sufficiently strong by itself to prop open a fracture. Another common problem is that the surface of the proppant may have an undesirable wettability characteristic for producing oil or gas from a particular subterranean formation. Another common problem is that, as the oil or gas moves through the subterranean formation, it can dislodge and carry particulate with the fluid into the wellbore. The migration of this particulate can plug pores in the formation or proppant pack, decreasing production, in addition to causing abrasive damage to wellbore pumps, tubing, and other equipment.
To help alleviate some of the common problems mentioned above, a resinous material can be coated on the proppant. The term “coated” does not imply any particular degree of coverage on the proppant particulates, which coverage can be partial or complete.
As used herein, the term “resinous material” means a material that is a viscous liquid and has a sticky or tacky characteristic when tested under standard laboratory conditions. A resinous material can include a resin, a tackifying agent, and any combination thereof in any proportion. The resin can be or include a curable resin.
Designing a Fracturing Treatment for a Treatment Zone
Designing a fracturing treatment usually includes determining a designed total pumping time for the treatment or determining a designed total pumping volume of fracturing fluid for the fracturing treatment. The tail end of a fracturing treatment is the last portion of pumping time into the zone or the last portion of the volume of fracturing fluid pumped into the zone. This is usually about the last minute of total pumping time or about the last wellbore volume of a fracturing fluid to be pumped into the zone. The portion of pumping time or fracturing fluid volume that is pumped before the tail end of a fracturing fluid reaches into a far-field region of the zone. In addition to being designed in advance, the actual point at which a fracturing fluid is diverted from a zone can be determined by a person of skill in the art, including based on observed changes in well pressures or flow rates.
Fracturing methods can include a step of designing or determining a fracturing treatment for a treatment zone of the subterranean formation prior to performing the fracturing treatment. For example, the step of designing can include: (a) determining the design temperature and design pressure; (b) determining the total designed pumping volume of the one or more treatment fluids to be pumped into the treatment zone at a rate and pressure above the fracture pressure of the treatment zone; (c) designing a treatment fluid, including its composition and rheological characteristics; (d) designing the pH of the continuous phase of the treatment fluid, if water-based; (e) determining the size of a proppant of a proppant pack previously formed or to be formed in fractures in the treatment zone; and (f) designing the loading of any proppant in the fluid.
“Carrier” Fluid for Suspending Particulate, Such as Cuttings, Proppant, or Gravel
A well fluid can be adapted to be a “carrier” fluid for a particulate.
For example, during drilling, rock cuttings should be carried uphole by the drilling fluid and flowed out of the wellbore. The rock cuttings typically have specific gravity greater than 2, which is much higher than that of many drilling fluids. These high-density cuttings have a tendency to separate from water or oil very rapidly.
Similarly, a proppant used in fracturing or a gravel used in gravel packing may have a much different density than the carrier fluid. For example, sand has a specific gravity of about 2.7, whereas water has a specific gravity of 1.0 at Standard Laboratory conditions of temperature and pressure. A proppant or gravel having a different density than water will tend to separate from water very rapidly.
As many well fluids are water-based, partly for the purpose of helping to suspend particulate of higher density, and for other reasons known in the art, the density of the fluid used in a well can be increased by including highly water-soluble salts in the water, such as potassium chloride. However, increasing the density of a well fluid will rarely be sufficient to match the density of the particulate.
Increasing Viscosity of Fluid for Suspending Particulate
Increasing the viscosity of a well fluid can help prevent a particulate having a different specific gravity than an external phase of the fluid from quickly separating out of the external phase.
A viscosity-increasing agent can be used to increase the ability of a fluid to suspend and carry a particulate material in a well fluid. A viscosity-increasing agent can be used for other purposes, such as matrix diversion or conformance control.
A viscosity-increasing agent is sometimes referred to in the art as a viscosifying agent, viscosifier, thickener, gelling agent, or suspending agent. In general, any of these refers to an agent that includes at least the characteristic of increasing the viscosity of a fluid in which it is dispersed or dissolved. There are several kinds of viscosity-increasing agents and related techniques for increasing the viscosity of a fluid.
In general, because of the high volume of fracturing fluid typically used in a fracturing operation, it is desirable to efficiently increase the viscosity of fracturing fluids to the desired viscosity using as little viscosity-increasing agent as possible. In addition, relatively inexpensive materials are preferred. Being able to use only a small concentration of the viscosity-increasing agent requires a lesser amount of the viscosity-increasing agent in order to achieve the desired fluid viscosity in a large volume of fracturing fluid.
Polymers for Increasing Viscosity
Certain kinds of polymers can be used to increase the viscosity of a fluid. In general, the purpose of using a polymer is to increase the ability of the fluid to suspend and carry a particulate material. Polymers for increasing the viscosity of a fluid are preferably soluble in the external phase of a fluid. Polymers for increasing the viscosity of a fluid can be naturally occurring polymers such as polysaccharides, derivatives of naturally occurring polymers, or synthetic polymers.
Water-Soluble Polymers for Increasing Viscosity of Aqueous Phase
Treatment fluids used in high volumes, such as fracturing fluids, are usually water-based. Efficient and inexpensive viscosity-increasing agents for water include certain classes of water-soluble polymers.
As will be appreciated by a person of skill in the art, the dispersability or solubility in water of a certain kind of polymeric material may be dependent on the salinity or pH of the water. Accordingly, the salinity or pH of the water can be modified to facilitate the dispersability or solubility of the water-soluble polymer. In some cases, the water-soluble polymer can be mixed with a surfactant to facilitate its dispersability or solubility in the water or salt solution utilized.
The water-soluble polymer can have an average molecular weight in the range of from about 50,000 to 20,000,000, most preferably from about 100,000 to about 4,000,000. For example, guar polymer is believed to have a molecular weight in the range of about 2 to about 4 million.
Typical water-soluble polymers used in well treatments include water-soluble polysaccharides and water-soluble synthetic polymers (e.g., polyacrylamide). The most common water-soluble polysaccharides employed in well treatments are guar and its derivatives.
Polysaccharides and Derivatives
As used herein, a “polysaccharide” can broadly include a modified or derivative polysaccharide.
As used herein, “modified” or “derivative” means a compound or substance formed by a chemical process from a parent compound or substance, wherein the chemical skeleton of the parent is retained in the derivative. The chemical process preferably includes at most a few chemical reaction steps, and more preferably only one or two chemical reaction steps. As used herein, a “chemical reaction step” is a chemical reaction between two chemical reactant species to produce at least one chemically different species from the reactants (regardless of the number of transient chemical species that may be formed during the reaction). An example of a chemical step is a substitution reaction. Substitution on a polymeric material may be partial or complete.
Single- or Multi-Chain Polymers
A polymer can be classified as being single chain or multi chain, based on its solution structure in aqueous liquid media. Examples of single-chain polysaccharides that are commonly used in the oilfield industry include guar, guar derivatives, and cellulose derivatives. Guar polymer, which is derived from the beans of a guar plant, is referred to chemically as a galactomannan gum. Examples of multi-chain polysaccharides include xanthan, diutan, and scleroglucan, and derivatives of any of these. Without being limited by any theory, it is currently believed that the multi-chain polysaccharides have a solution structure similar to a helix or are otherwise intertwined.
Form and Concentration of Viscosity-Increasing Agent
The viscosity-increasing agent may be provided in any form that is suitable for the particular treatment fluid or application of the present invention. The viscosity-increasing agent can be provided as a liquid, gel, suspension, or solid additive that is admixed or incorporated into a treatment fluid used in conjunction with the present invention. The viscosity-increasing agent can also be present in a solid particulate form of any size or shape. For example, larger sized particulates of spherical shape can be used, inter alia, to form perforation tunnel blocking particles, similar to perforation pack balls. Similarly, smaller sized particulates can be used, inter alia, as a fluid-loss control material that may act to bridge natural fractures or other channels.
The viscosity-increasing agent should be present in a treatment fluid in a form and in an amount at least sufficient to impart the desired viscosity to a treatment fluid. For example, the amount of viscosity-increasing agent used in the treatment fluids suitable for use in the present invention may vary from about 0.25 pounds per 1,000 gallons of treatment fluid (“lbs/Mgal”) to about 200 lbs/Mgal. In other embodiments, the amount of viscosity-increasing agent included in the treatment fluids suitable for use in the present invention may vary from about 10 lbs/Mgal to about 80 lbs/Mgal. In another embodiment, about 20 pounds to about 70 pounds (lbs) of water-soluble polymer per 1,000 gallons (Mgal) of water (equivalent to about 2.4 g/L to about 8.4 g/L).
Crosslinking of Polymer to Increase Viscosity of a Fluid or Form a Gel
The viscosity of a fluid at a given concentration of viscosity-increasing agent can be greatly increased by crosslinking the viscosity-increasing agent. A crosslinking agent, sometimes referred to as a crosslinker, can be used for this purpose. A crosslinker interacts with at least two polymer molecules to form a “crosslink” between them.
If crosslinked to a sufficient extent, the polysaccharide may form a gel with water. Gel formation is based on a number of factors including the particular polymer and concentration thereof, the particular crosslinker and concentration thereof, the degree of crosslinking, temperature, and a variety of other factors known to those of ordinary skill in the art.
A “base gel” is a term used in the field for a fluid that includes a viscosity-increasing agent, such as guar, but that excludes crosslinking agents. Typically, a base gel is a fluid that is mixed with another fluid containing a crosslinker, wherein the mixed fluid is adapted to form a gel. A base gel can be used, for example, as an external phase of an emulsion.
For example, one of the most common viscosity-increasing agents used in the oil and gas industry is guar. A mixture of guar dissolved in water forms a base gel, and a suitable crosslinking agent can be added to form a much more viscous fluid, which is then called a crosslinked fluid. The viscosity of base gels of guar is typically about 20 to about 50 cp. When a base gel is crosslinked, the viscosity is increased by 2 to 100 times depending on the temperature, the type of viscosity testing equipment and method, and the type of crosslinker used.
The degree of crosslinking depends on the type of viscosity-increasing polymer used, the type of crosslinker, concentrations, temperature of the fluid, etc. Shear is usually required to mix the base gel and the crosslinking agent. Thus, the actual number of crosslinks that are possible and that actually form also depends on the shear level of the system. The exact number of crosslink sites is not well known, but it could be as few as one to about ten per polymer molecule. The number of crosslinks is believed to significantly alter fluid viscosity.
For a polymeric viscosity-increasing agent, any crosslinking agent that is suitable for crosslinking the chosen monomers or polymers may be used.
Some crosslinking agents form substantially permanent crosslinks with viscosity-increasing polymer molecules. Such crosslinking agents include, for example, crosslinking agents comprising at least one metal ion that is capable of crosslinking gelling agent polymer molecules. Examples of such crosslinking agents include, but are not limited to, zirconium compounds (such as, for example, zirconium lactate, zirconium lactate triethanolamine, zirconium carbonate, zirconium acetylacetonate, zirconium maleate, zirconium citrate, zirconium oxychloride, and zirconium diisopropylamine lactate); titanium compounds (such as, for example, titanium lactate, titanium maleate, titanium citrate, titanium ammonium lactate, titanium triethanolamine, and titanium acetylacetonate); aluminum compounds (such as, for example, aluminum acetate, aluminum lactate, or aluminum citrate); antimony compounds; chromium compounds; iron compounds (such as, for example, iron chloride); copper compounds; zinc compounds; sodium aluminate; or a combination thereof.
Crosslinking agents can include a crosslinking agent composition that may produce delayed crosslinking of an aqueous solution of a crosslinkable organic polymer, as described in U.S. Pat. No. 4,797,216, the entire disclosure of which is incorporated herein by reference. Crosslinking agents can include a crosslinking agent composition that may comprises a zirconium compound having a valence of +4, an alpha-hydroxy acid, and an amine compound as described in U.S. Pat. No. 4,460,751, the entire disclosure of which is incorporated herein by reference.
Some crosslinking agents do not form substantially permanent crosslinks, but rather chemically labile crosslinks with viscosity-increasing polymer molecules. For example, a guar-based gelling agent that has been crosslinked with a borate-based crosslinking agent does not form permanent cross-links.
Sometimes, however, crosslinking is undesirable, as it may cause the polymeric material to be more difficult to break and it may leave an undesirable residue in the formation.
Breaker for Viscosity of Fluid with Polysaccharide or Crosslinked Polysaccharide
After a treatment fluid is placed where desired in the well and for the desired time, the fluid usually must be removed from the wellbore or the formation. For example, in the case of hydraulic fracturing, the fluid should be removed leaving the proppant in the fracture and without damaging the conductivity of the proppant bed. To accomplish this removal, the viscosity of the treatment fluid must be reduced to a very low viscosity, preferably near the viscosity of water, for optimal removal from the propped fracture. Similarly, when a viscosified fluid is used for gravel packing, the viscosified fluid must be removed from the gravel pack.
Reducing the viscosity of a viscosified fluid is referred to as “breaking” the fluid. Chemicals used to reduce the viscosity of fracturing fluids are called breakers. Other types of viscosified well fluids also need to be broken for removal from the wellbore or subterranean formation.
No particular mechanism is necessarily implied by the term. For example, a breaker can reduce the molecular weight of a water-soluble polymer by cutting the long polymer chain. As the length of the polymer chain is cut, the viscosity of the fluid is reduced. For instance, reducing the guar polymer molecular weight to shorter chains having a molecular weight of about 10,000 converts the fluid to near water-thin viscosity. This process can occur independently of any crosslinking bonds existing between polymer chains.
In the case of a crosslinked viscosity-increasing agent, for example, one way to diminish the viscosity is by breaking the crosslinks. For example, the borate crosslinks in a borate-crosslinked polymer can be broken by lowering the pH of the fluid. At a pH above 8, the borate ion exists and is available to crosslink and cause an increase in viscosity or gelling. At a lower pH, the borate ion reacts with proton and is not available for crosslinking, thus, an increase in viscosity due to borate crosslinking is reversible. In contrast, crosslinks formed by zirconium, titanium, antimony, and aluminum compounds, however, are such crosslinks are considered to be non-reversible and are broken by other methods than controlling pH.
Thus, removal of the treatment fluid is facilitated by using one or more breakers to reduce fluid viscosity.
Unfortunately, another complicating factor exists. Because of the large size of the polymer, a filtration process can occur upon the face of a formation or fracture in conventional formation. A filtercake of the polymer can be formed while the aqueous fluid, KCl, and breakers pass into the matrix of the formation. Careful examination of this filtercake, which may be formed from crosslinked or uncrosslinked guar or other polymer, reveals a semi-elastic, rubberlike membrane. Once the polymer concentrates, it is difficult to solubilize the polymer. Nonfiltercake fluid consists of approximately 99.5 percent water and 0.5 percent polymer. Accordingly, for example, when the fracture closes in a fracturing treatment, the permeability of the proppant bed or the formation face may be severely damaged by the polymer filtercake. Viscosified gravel pack fluids need breakers, too. They may or may not form a filtercake on the formation face.
Breakers must be selected to meet the needs of each situation. First, it is important to understand the general performance criteria of breakers. In reducing the viscosity of the treatment fluid to a near water-thin state, the breaker must maintain a critical balance. Premature reduction of viscosity during the pumping of a treatment fluid can jeopardize the treatment. Inadequate reduction of fluid viscosity after pumping can also reduce production if the required conductivity is not obtained.
In fracturing, for example, the ideal viscosity versus time profile would be if a fluid maintained 100% viscosity until the fracture closed on proppant and then immediately broke to a thin fluid. Some breaking inherently occurs during the 0.5 to 4 hours required to pump most fracturing treatments. One guideline for selecting an acceptable breaker design is that at least 50% of the fluid viscosity should be maintained at the end of the pumping time. This guideline may be adjusted according to job time, desired fracture length, and required fluid viscosity at reservoir temperature. A typical gravel pack break criteria is a minimum 4-8 hour break time. On the other hand, long break times, especially if greater than two days, are undesirable.
Chemical breakers used to reduce viscosity of a fluid viscosified with a viscosifying polymer used in fracturing or other subterranean applications are generally grouped into three classes: oxidizers, enzymes, and acids. In general, the breakers operate by cleaving the backbone of polymer either by hydrolysis of acetyl group, cleavage of glycosidic bonds, oxidative/reductive cleavage, free radical breakage or combination of these processes. A breaker should be selected based on its performance in the temperature, pH, time, and desired viscosity profile for each specific treatment.
Oxidizer Breakers
Oxidizers commonly used to reduce viscosity of natural polymers includes, for example, sodium persulfate, potassium persulfate, ammonium persulfate, lithium or sodium hypochlorites, chlorites, peroxide sources (sodium perborate, sodium percarbonate, calcium percarbonate, urea-hydrogen peroxide, hydrogen peroxide, etc.), bromates, periodates, permanganates, etc. In these types of breakers, oxidation reduction chemical reactions occur as the polymer chain is broken.
Different oxidizers are selected based on their performance at different temperature and pH ranges. Consideration is also given to the rate of oxidation at a particular temperature and pH range. For example, the rate at which a persulfate molecule breaks into two radicals is temperature dependent. Below 120° F. (49° C.) this process occurs very slowly, and the reaction can be catalyzed to obtain acceptable break rates. A variety of catalysts, including various organic amines, can be used for persulfate breakers. The optimum pH for persulfate oxidation is around 10 at low temperature (less than 150° F. or 66° C.). Above approximately 200° F. (93° C.), persulfate decomposes very quickly and breaks the polymer very quickly (i.e., with little delay in the break). Therefore, persulfate is generally not recommended as a breaker above about 200° F. Similarly chlorites are used for high temperature breakage in the range of about 150° F. to about 350° F. with optimum pH range of 6-12. Some breakers can also be activated by catalysts such as cobalt acetate, EDTA, NTA, etc. to function at different temperature ranges. Hypochlorites are generally used for low temperature breakage of natural polymers.
Controlling Break Time
A breaker may be included in a treatment fluid in a form and concentration at selected to achieve the desired viscosity reduction at a desired time.
The breaker may be formulated to provide a delayed break, if desired. For example, a suitable breaker may be encapsulated if desired. Suitable encapsulation methods are known to those skilled in the art. One suitable encapsulation method involves coating the selected breaker in a porous material that allows for release of the breaker at a controlled rate. Another suitable encapsulation method that may be used involves coating the chosen breakers with a material that will degrade when downhole so as to release the breaker when desired. Resins that may be suitable include, but are not limited to, polymeric materials that will degrade when downhole.
A treatment fluid can optionally comprise an activator or a retarder to, among other things, optimize the break rate provided by a breaker. Examples of such activators include, but are not limited to, acid generating materials, chelated iron, copper, cobalt, and reducing sugars. Examples of retarders include sodium thiosulfate, methanol, and diethylenetriamine.
Delayed breakers, activators, and retarders can be used to help control the breaking of a fluid, but these may add additional complexity and cost to the design of a treatment fluid.
Potential Sources of Water for Use in Treatment Fluids
Non-freshwater sources of water can include surface water ranging from brackish water to seawater, brine, returned water (sometimes referred to as flowback water) from the delivery of a well fluid into a well, unused well fluid, and produced water. As used herein, brine refers to a water having at least 40,000 mg/L total dissolved solids.
In the production of oil and gas, great quantities of water are produced. Sources of produced water can include water that may have been introduced into the subterranean formation as part of a well-completion or well-treatment process, water that may have been delivered as part of an injection-well driving process, formation water, and any mixture of any of these. For example, for every barrel of oil produced from a well, it is typical to also obtain about 10 barrels of produced water. Large quantities of produced water continue to be disposed of as wastewater, for example, by re-injecting the produced water into a well.
With the rising demand for potable water and freshwater, increasing public concern for the environment, and with the rising costs of obtaining potable water and freshwater, it would be desirable to be able to use lower quality water, such as returned water and produced water, in well treatments.
Unfortunately, unused well fluid, returned water, and produced water often has high concentrations of total dissolved solids (salts), and may have TDS levels of brackish water, seawater, or brine. Returned water and produced water may also contain hydrocarbon and other materials. For example, in addition to dissolved and suspended solids, produced water may also contain residual oil, grease, and production chemicals. A production chemical is a chemical that was introduced into the subterranean formation in a prior well treatment and may be found in subsequently produced water. An example of a production chemical would include residual viscosity-increasing agent, including, for example, non-crosslinked or crosslinked polysaccharides.
It is recognized that, in general, for water to be suitable for use in common well treatments, usually all that is required is that the water does not contain one or more materials that would be particularly detrimental to the chemistry involved in such well treatments.
For example, the water is preferably cleaned of undissolved, suspended solids (e.g., silt) to a point that the natural permeability and the conductivity of the fracture will not be damaged. For this purpose, all the water used in a well treatment may be filtered to help reduce the concentration of suspended, undissolved solids that may be present in the water, such as silt.
In some cases, a returned water (aka flow back water) can have an undesirably high viscosity due to a residual viscosity-increasing polymer, which may or may not be cross-linked, that was not completely broken in the well before flowing back. To use such a returned water in forming another well fluid, it may be necessary to break the residual viscosity.
Further, it is recognized that it is even possible to use such water having undesirable concentrations of certain ions or TDS if the water is used as part of the treatment fluid, and the treatment fluid is formed in using the water in a proper sequence.
Of particular concern for use in common well treatment is the avoidance of water containing undesirably-high concentrations of inorganic ions having a valence state of two or more. As is well known in the oil and gas industry, such ions can interfere with the chemistry of forming or breaking certain types of viscous fluids that are commonly used in various well treatments.
Cations that are of common concern include dissolved alkaline earth metal ions, particularly calcium and magnesium ions, and may include dissolved iron(II) or iron(III) ions. Even at higher pH ranges, ferric ion can be dissolved itself or as part of a water-soluble complexes with many inorganic and organic ligands, including compounds that are the byproducts of the biodegradation of aromatic petroleum hydrocarbons.
An anion of common concern includes sulfate.
Normally, however, a high concentration of both calcium ions and sulfate anions in a water source is unlikely. Calcium ions tend to react with sulfate ions to produce calcium sulfate, which is an insoluble salt [0.21 g/100 ml at 20° C. (anhydrous) or 0.24 g/100 ml at 20° C. (dihydrate)] that tends to precipitate from solution. Similarly, strontium ions and sulfate ions or barium ions and sulfate ions tend to combine and precipitate. Thus, a problem with using water for common well treatments tends to be either an undesirably-high concentration of calcium, strontium, or barium ions or an undesirably-high concentration of sulfate ions.
Borates have the chemical formula B(OR)3, where B=boron, O=oxygen, and R=hydrogen or any organic group. At higher pH ranges, e.g., 8 or above, a borate is capable of increasing the viscosity of an aqueous solution of a water-soluble polymeric material such as a galactomannan or a polyvinyl alcohol. Afterwards, if the pH is lowered, e.g., below 8, the observed effect on increasing the viscosity of the solution can be reversed to reduce or “break” the viscosity back toward its original lower viscosity. It is also well known that, at lower pH ranges, e.g., below 8, borate does not increase the viscosity of such a water-soluble polymeric material. This effect of borate and response to pH provides a commonly used technique for controlling the cross-linking of certain polymeric viscosity-increasing agents. The control of increasing the viscosity of such fluids and the subsequent “breaking” of the viscosity tends to be sensitive to several factors, including the particular borate concentration in the solution. Borate cross-linking may be undesirable in some well treatments, however, which may interfere with the desired chemistry for a particular well treatment. Thus, the presence of borates or the presence of unknown concentrations of borates is often undesired.
As used herein, a substantial concentration of sulfate ions is defined as being equal to or greater than 500 ppm; a substantial concentration of calcium or magnesium ions is defined as being equal to or greater than a combined total of 1,000 ppm; a substantial concentration of iron ions (ferrous and ferric) is defined as being equal to or greater than 5 ppm; a substantial concentration of borate is defined as being equal to or greater than 5 ppm.
One attempted solution has been to treat the water to remove some of the interfering ions. There are several existing methods of treating non-freshwater such as evaporative distillation and reverse osmosis. Both of these treatment methods remove the vast majority of TDS from the water. Removing excess ions by distillation or reverse osmosis is an expensive process. Of course, the costs of treating water are multiplied by the large volumes of water required for well treatments, especially for the volumes of water required for water-fracturing treatments.